This invention relates generally to a method and system for treating a subterranean formation using diversion.
Wellbore treatment methods often are used to increase hydrocarbon production by using a treatment fluid to affect a subterranean formation in a manner that increases oil or gas flow from the formation to the wellbore for removal to the surface. Hydraulic fracturing and chemical stimulation are common treatment methods used in a wellbore. Hydraulic fracturing involves injecting fluids into a subterranean formation at such pressures sufficient to form fractures in the formation, the fractures increasing flow from the formation to the wellbore. In chemical stimulation, flow capacity is improved by using chemicals to alter formation properties, such as increasing effective permeability by dissolving materials in or etching the subterranean formation. A wellbore may be an open hole or a cased hole where a metal pipe (casing) is placed into the drilled hole and often cemented in place. In an open hole, a slotted liner or screen may be installed. In a cased wellbore, the casing (and cement if present) typically is perforated in specified locations to allow hydrocarbon flow into the wellbore or to permit treatment fluids to flow from the wellbore to the formation.
To access hydrocarbon effectively and efficiently, it is desirable to direct the treatment fluid to target zones of interest in a subterranean formation. There may be target zones of interest within various subterranean formations or multiple layers within a particular formation that are preferred for treatment. In such situations, it is preferred to treat the target zones or multiple layers without inefficiently treating zones or layers that are not of interest. In general, treatment fluid flows along the path of least resistance. For example, in a large formation having multiple zones, a treatment fluid would tend to dissipate in the portions of the formation that have the lowest pressure gradient or portions of the formation that require the least force to initiate a fracture. Similarly in horizontal wells, and particularly those horizontal wells having long laterals, the treatment fluid dissipates in the portions of the formation requiring lower forces to initiate a fracture (often near the heel of the lateral section) and less treatment fluid is provided to other portions of the lateral. Also, it is desirable to avoid stimulating undesirable zones, such as water-bearing or non-hydrocarbon bearing zones. Thus it is helpful to use methods to divert the treatment fluid to target zones of interest or away from undesirable zones.
Diversion methods are known to facilitate treatment of a specific interval or intervals. Ball sealers are mechanical devices that frequently are used to seal perforations in some zones thereby diverting treatment fluids to other perforations. In theory, use of ball sealers to seal perforations permits treatment to proceed zone by zone depending on relative breakdown pressures or permeability. But frequently ball sealers prematurely seat on one or more of the open perforations, resulting in two or more zones being treated simultaneously. Likewise, when perforated zones are in close proximity, ball sealers have been found to be ineffective. In addition, ball sealers are useful only when the casing is cemented in place. Without cement between the casing and the borehole wall, the treatment fluid can flow through a perforation without a ball sealer and travel in the annulus behind the casing to any formation. Ball sealers have limited use in horizontal wells owing to the effects of formation pressure, pump pressure, and gravity in horizontal sections, as well as that possibility that laterals in horizontal wells may not be cemented in place.
Changes in pumping pressures are used to detect whether ball sealer have set in perforations; this inherently assuming that the correct number of ball sealers were deployed to seal all the relevant perforations and that the balls are placed in the correct location for diverting the treatment fluids to desired zones. Other mechanical devices known to be used for used for diversion include bridge plugs, packers, down-hole valves, sliding sleeves, and baffle/plug combinations; and particulate placement. As a group, use of such mechanical devices for diversion tends to be time consuming and expensive which can make them operationally unattractive, particularly in situations where there are many target zones of interest. Chemically formulated fluid systems are known for use in diversion methods and include viscous fluids, gels, foams, or other fluids. Many of the known chemically formulated diversion agents are permanent (not reversible) in nature and some may damage the formation. In addition, some chemical methods may lack the physical structure and durability to effectively divert fluids pumped at high pressure or they may undesirably affect formation properties. The term diversion agent herein refers to mechanical devices, chemical fluid systems, combinations thereof, and methods of use for blocking flow into or out of a particular zone or a given set of perforations.
In operation, it is preferred that the treatment fluid enters the subterranean formation only at the target zones of interest. It is more preferred that the treatment fluid treatment enters the subterranean formation on a stage-by-stage basis. But known disadvantages to existing diversion methods do not permit a level of confidence or certainty as to where the diversion agent is placed, whether single treatment stages are being accomplished, whether target zones of interest are treated, as well as the order of treatment of the target zones.
What is needed is a reliable method of selectively and efficiently treating target zones in a subterranean formation using a diversion agent and monitoring during the treatment.